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The understanding of proppant flow through fractures is critical in evaluating the performance of hydraulic fracturing operations. As a continuation of our experimental efforts devoted to understanding how proppant flows in rough vertical fractures, in this paper, we examine the effect of injection parameters on the proppant transport in rough vertical fractures. The effects of polymer concentration, injection rate, proppant concentration, and type of proppant were investigated in detail. Experimental results show that, in general, two types of settling patterns can be observed in the proppant transport in a rough fracture: sand-dune settling pattern and tree-like settling pattern. The following conditions tend to suppress the tree-like settling behavior of proppants in the rough fracture: a higher density of the proppants, a lower viscosity of the polymer solution, and a lower injection rate. This is attributed to a higher settling velocity of the proppants in the fracture under these conditions. A sufficiently high polymer concentration is needed to enable effective proppant flow in rough fractures. In general, the relative coverage of proppants increased dramatically as the polymer concentration increased, implying that the higher viscosity of fracturing fluid could enhance the slurry's ability to place more proppant vertically into the fracture and help to maintain a better conductivity after fracturing treatment. A sufficiently high injection rate of the slurry is also needed to enable effective proppant flow in rough fractures. At certain low injection rates, the proppants carried by a low polymer solution might not exhibit a tree-like settling pattern, diminishing the effect of roughness on the proppant transport. This means that even in rough fractures, the tree-like settling pattern of the proppants did not necessarily occur for sure; the injection rate should be properly selected to enable such phenomenon. With other conditions being kept constant, a higher proppant loading led to a higher final relative coverage of the proppants in the rough fractures. But if the injection rate used for delivering the proppants is not sufficiently high, we may encounter injectivity issues; in our lab experiments, this caused the choking of the pump. The heavier proppant (ceramic proppants) in the rough fracture models tended to suppress the tree-like settling pattern that was experienced by the lighter proppant (silica sands). This is attributed to the larger density of the ceramic proppants, leading to a larger settling velocity. In order to maximize the spreading of a given proppant over a rough fracture model, we should determine the proper values of all the essential injection parameters (including polymer solution, injection rate, proppant concentration) by striking a good balance among them. The conclusions obtained in this study shed light on how to optimize slurry injection parameters to achieve an optimal proppant-filling ratio during hydraulic fracturing. • We experimentally study proppant slurry flow through a rough vertical fracture. • Proppant transport in a rough vertical fracture is very different that in a smooth vertical fracture. • Proppant bed forms a tree-like pattern when they are settling down in a rough vertical fracture. • Heavier proppants in rough vertical fracture tends to suppress the tree-like settling pattern compared to a lighter one. [ABSTRACT FROM AUTHOR]

Clay stabilizer is the topic of a great number of studies, particularly in petroleum engineering. The organic cationic polymer is a kind of clay stabilizer with excellent anti-swelling effect. However, for tight reservoirs, the organic cationic polymer type clay stabilizers tend to increase the permeability damage caused by retention and blockage of stabilizers. Therefore, stabilizers with low molecular weight are necessary for tight reservoirs. The inhibition properties and the mechanisms of ethylenediammonium dichloride (EDD) were studied in this paper. The clay inhibition properties were studied from three aspects: swelling inhibition, clay sedimentation, and particle size distribution. Results showed that the anti-swelling rate reaches 91.98%. Control experiments showed that EDD had better inhibition property than KCl, NH 4 Cl, and poly dimethyldiallyl ammonium chloride (PDMDAAC). The inhibition mechanisms, studied from the aspect of surface hydrophobicity, surface charge, interlayer water content, and crystal spacing, can be concluded as that EDD reduces clay electronegativity and enhances the hydrophobicity of the clay surface, thereby keeping clay in a stable state. Compatibility tests showed that EDD can be used in guar based fracturing fluid. This study provides an alternative clay stabilizer for hydraulic fracturing. • The anti-swelling rate of ethylenediammonium dichloride for Na-MT is 91.98%. • Ethylenediammonium dichloride exhibits better clay inhibition property than PDMDAAC. • It enhances the hydrophobicity, prevents water adsorption, and weakens the hydration of clay particles. • It reduces the surface charge, squeeze out the interlayer water, and compress the crystal spacing. • It exhibits excellent compatibility with the guar based fracturing fluid. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is one of the primary techniques which has been widely implemented in order to allow for the stimulation of shale gas reservoirs. To accurately distinguish the extension characteristics and the spatial distribution of fractures during the hydraulic fracturing of the Longmaxi shale reservoirs in Changning, a self-developed, multifunctional, true triaxial experimental process (utilizing a fluid-solid coupling testing system) was used to simulate the horizontal well hydraulic fracturing. The CT technique was used to scan the samples prior to and following the conduction of the experiments; the CT scanning images of internal fractures were reconstructed and visualized via 3D reconstruction. The influence of in-situ stress, the displacement of the fracturing fluid upon the fracture morphology and the resultant fractural extensions caused by hydraulic fracturing were discussed. The study shows that the reconstructed 3D model based on the different CT values corresponding to the shale matrix, minerals and fractures can accurately characterize the internal structure and fracture distribution of shale. Shale hydraulic fracturing fractures can be divided into 3 categories: single transverse fractures, main arc fractures and complex fractures. The "fluctuation phenomenon" of a water pressure curve is related to the formation and extension of reservoir fractures, and is a discernible characteristic of complex fractures formed by the volume fracturing of shale. Stress differences and the stress difference coefficient are the governing factors in terms of the complexity of shale hydraulic fracturing networks. Displacement has a particular range of influence on the manifestation of fracture complexity; a low displacement may not result in a complete fracture, but too high a displacement tends to culminate a single fracture in the formation, which to a certain extent reduces fractural complexity. • Hydraulic fracturing experiment of shale under a self-developed true triaxial test system. • Visualization of 3D reconstruction of CT scanning images of the experimental samples • The experimental conditions were first time set according to the engineering geological features unique to the shale. • The influence of multiple factors on fracture morphology of shale fractures were studied [ABSTRACT FROM AUTHOR]

An enormous amount of fracturing fluid is irreducible in the tight formation after hydraulic fracturing stimulation. This will cause serious damage to the fracture face as well as the matrix close to the hydraulic fractures by invading into the matrix. Modeling the effect of water blockage on rate transient behavior is significant in reservoir engineering. This paper presents a modified trilinear model to analyze the rate transient behavior after flowback period. Single-phase flow is assumed in this stage because most injected water is hard to be reduced. For damage to the matrix caused by rock-fluid interaction, clay swelling, and polymer adsorption, a fracturing fluid invasion layer is added to the model between hydraulic fractures and the inner stimulated reservoir volume to capture this kind of damage. A skin factor is used to capture the damage to the matrix-fracture face caused by gel filter cake formation and polymer adsorption. The analytical model is benchmarked using the commercial numerical simulator Eclipse. Several synthetic cases and a field case are studied, the results show that water blockage has a great impact on the productivity of the well and decline curves. The effect of choking effect, convergence flow, and gel filter cake could be incorporated using a skin factor in the model. In addition, two more flow regimes could be observed on the theoretical type curve if the well is affected by water blockage, and the two flow regimes would happen before linear flow dominated by the inner stimulated zone. Besides, the duration of the inner zone linear flow regime could be shortened if the permeability of the fracturing fluid invasion layer is lower and invasion depth is larger. These phenomena can be used in matching the field production data from water blockage affected wells, which exhibit a transition flow regime before the formation linear flow regime. This transition flow regime could be matched quite better using the proposed model than the classical trilinear flow model. The reason is that the linear flow regime could be much longer if the water blockage effect is not considered in the model. On the other hand, the skin factor has a different impact on the flow regimes, so the water blockage effect could be characterized properly only by adding a skin factor to the model. The main contribution of this paper is the provision of an analytical model for evaluating the formation damage caused by irreducible fracturing fluid, analyzing production data and making forecasts. • An analytical model is proposed to model fracturing fluid-induced formation damage. • Different kinds of damage mechanisms are represented in different approaches. • The effect of water blockage on rate transient responses is detailed analyzed. • Field studies show that the proposed model is practical and efficient in analysis. [ABSTRACT FROM AUTHOR]

Understanding the factors controlling the fracturing fluid leak-off due to forced imbibition during the hydraulic fracturing operations is critical for the accurate assessment of the fracturing fluid invasion depth and the extent of the formation damage in gas shales. Here, we present results of an experimental and a modeling study of the factors controlling fracturing fluid forced imbibition into the organic rich shale gas reservoirs. The main objectives of the study were to: i-) Experimentally investigate the forced imbibition of the brine and the slick water (SW) into the shale; ii-) Develop an analytical model of the fracturing fluid forced imbibition into the shale matrix. The shale samples collected from Silurian Longmaxi (SL) Shale Formation, which is located in Southern Sichuan Basin in China, were used to conduct the forced imbibition experiments. Effects of varying fluid properties (i.e., the viscosity and the surface tension), the direction of the imbibition with respect to the shale bedding plane/lamination, and the fluid pressure across the shale face on the cumulative mass of the imbibed fluid per unit area over time were investigated. A new analytical model of the forced imbibition into a shale rock was developed. The Hagen-Poiseuille law and the capillary tube bundles model were used to describe flow through tortuous capillary. The new model also considered the effects of the fluid pressure across the rock face (i.e., forced imbibition) and the viscous pressure loss in the capillary. Comparison of the model predictions with the experimental results indicated that the effects of the fluid pressure and viscous pressure loss on the imbibed fluid mass are not negligible. The close agreement with the model predictions and experimental results in the direction parallel to shale lamination confirmed that the new model accurately describes the process of fracturing fluid forced imbibition into the shale matrix in the direction parallel to shale bedding plane. The new model could potentially be used for the field scale prediction of the average depth of fluid invasion into the shale matrix in the direction parallel to lamination due to the forced imbibition of the fracturing fluid. • Experimentally investigate the forced imbibition of the brine and the slick water into the shale matrix. • Developed an analytical model for forced imbibition based on Hagen-Poiseuille law and capillary tube bundles model. • The new model could potentially be used for field scale prediction in some case. [ABSTRACT FROM AUTHOR]

Given the limited successes of hydraulic fracturing in enhanced geothermal systems (EGS), understanding of the hydraulic fracturing characteristics in high-temperature granites remains challenging and crucial. In this study, four groups of cube granite specimens (dimensions: 300 / 300 / 300 mm) were tested to investigate the characteristics of the hydraulic fracture, for two confining pressures (0.1 / 0.1 / 0.1 MPa and 10 / 25 / 30 MPa) and temperatures (20 °C and 120 °C). Acoustic emission (AE) was employed to characterize the hydraulic fracturing processes. The experimental results show that for different temperatures the fracture geometry is almost unchanged, whereas the injection pressure curves, spatial distribution of AE energy, and AE-based source mechanisms are significantly changed. (1) At 120 °C , The fracture pressures are increased by 3.6 ~ 4.9 MPa and two remarkable pressure peaks appear at the injection pressure curves, implying the hydraulic fracture propagates intermittently with increasing resistances. (2) The spatial distributions of AE energy delineate a microcrack-band distributing along the hydraulic fracture. At the high temperature (120 °C), the effective width of the microcrack-band is reduced by 40~56.4%, and the fracture energy is reduced by about 75% adjacent to the wellbore (about 40% of the fracture length) in the microcrack-band. (3) Based on the AE source analysis, the fracture mechanisms in the microcrack-band indicate the high-temperature (120 °C) reduces the proportion of shear microcracks by 6~12%. The characteristics of high-temperature reducing the effectiveness of EGS hydraulic fracturing are due to the change in granite microstructures from temperature induction and the transient temperature differential (Δ T) between granite and fracturing fluid. In the EGS hydraulic fracturing, the net pressure should be enhanced in real-time with hydraulic fracture propagation to avoid fracturing arrest, Δ T between high-temperature granite and fracturing fluid should be lowered to enlarge the stimulated reservoir volume, and the proppant is suggested to be appropriately placed to prevent the further reduction of the fracturing effectiveness from fracture closures. • Hydraulic fracture (HF) grows intermittently at high temperatures. • Fracture energy, constant normally, elevates as fracture extends at 120 °C. • High temperatures induce restricted microcrack-bands at both sides of HF. • The induced microcrack-bands contribute to productivity positively. • Shear component in microcrack-band takes lesser proportion when temperature rises. [ABSTRACT FROM AUTHOR]

The application of horizontal drilling and hydraulic fracturing stimulations for improving hydrocarbon productivity from low-permeable reservoirs is a well-established practice. However, the development of fracturing fluids that can maintain excellent rheological properties at reservoir conditions, as well as, minimize damage to the formation is still very challenging. There has been increasing interest in recent years in the improvement of the hydraulic fracturing stimulation through the application of nanotechnology. We review the current status of nanoparticles applications for hydraulic fracturing treatments of the unconventional reservoirs, highlighting the mechanisms and applications, the findings, the technical challenges and directions for future studies. The review literature demonstrated the promising applications of nanomaterials for improving the rheology of viscoelastic surfactant fluid, foam-based fluid and polymer-based fracturing fluid using nano-crosslinker and bio-polymer nano-composite. Results of previous studies showed that the unique properties of nano-materials, such as their smaller sizes, high specific surface area, magnetic properties, superior strength and stability could be exploited in the development of downhole nano-sensors, nano-proppants, gel breakers and fluid loss control agents. More work will be required to understand the cross-linking mechanisms of nano-crosslinkers and the mechanisms governing the enhancement in fracturing fluid viscosity in presence of nanoparticles at reservoir conditions. The potential applications of generally used nanoparticles such as, aluminum oxide (Al 2 O 3), Copper oxide (CuO), carbon nanotubes and low cost nanoparticles such as calcium carbonate (CaCO 3), silicon dioxide (SiO 2) and fly-ash nanoparticles in unconventional reservoirs need to be further researched. Moreover, more emphasize should be place on nanoparticles performance at reservoir conditions, influence of nanoparticles agglomeration, economic feasibility, as well as environmental and health hazards of nanoparticles applications. The improved hydrocarbon recovery from the unconventional reservoirs through wettability alterations and interfacial tension reduction by nanofluids, and the use of nanoparticles-enhanced combined fracturing fluid systems present exciting future opportunities. Image 1 • Improved hydraulic fracturing stimulation through nanotechnology is trending. • Application of nanoparticles as nanosensors, nanoproppants and gel breakers is promising. • Nanoparticles performance at reservoir conditions needs further investigation. • Nanoparticles agglomeration and cost of nanoparticles could hinder field applications. [ABSTRACT FROM AUTHOR]

Abstract Most fracturing treatments today require injecting solid proppants to keep hydraulic fractures open. However, traditional proppants have disadvantages such as causing the reduced propped-fracture volume and abrasion to the pumping equipments and tubulars. To solve these problems, a new self-generating solid proppant has been developed through liquid-solid transition of self-propping fracturing fluid under reservoir conditions. To select the best self-generating solid proppant and compare it with conventional ones, physical property and fracture conductivity tests were done. Experimental results show that two self-generating solid proppants, including S101 and S505, are firstly selected because of their low density, high strength and excellent fracture conductivity. The apparent density is 1.09 g/cm3 for S101 and 1.10 g/cm3 for S505. The crushing rate of S101 is 1.47% while that of S505 is 1.29%. These data illustrate physical properties of self-generating solid proppant are obviously better than those of conventional proppants. Under the same conditions, the larger the spherical particle size of S101 and S505, the higher the fracture conductivity. Non-uniform distribution of proppant pack can increase fracture conductivity. Fracture conductivities of S101 and S505 are higher than that of quartz sand, and even higher than that of ceramsite at low closure stresses. Based on the experimental results, the pumping rate and injecting proportion of self-propping fracturing fluid can be optimized during the fracturing process. Graphical abstract Image 1 Highlights • Self-generating solid proppant is formed in the formation fracture. • The physical property of self-generating solid proppant is better than that of conventional proppant. • The fracture conductivity of self-generating solid proppant is higher than that of conventional proppant. [ABSTRACT FROM AUTHOR]

Abstract Hydraulic fracturing is widely applied in tight reservoirs for hydrocarbon recovery. However, as for bottom-water reservoirs, the created vertical hydraulic fractures can readily penetrate into the bottom-water layer, leading to a drastic increase of water cut when the pay-zones are too thin and the barrier lying between the pay-zone and bottom water are quite weak. In this work, a new sinking agent is used in hydraulic fracturing for water control in the low-permeability/bottom-water reservoirs. The settlement velocity and the plugging ability of this new sinking agent as well as the flow conductivity of the sinking-agent barrier is measured and compared with that of the other six commonly used sinking agents. We finally investigate the placement rule of the new sinking agent by varying the concentration of the carrying fluid and sand ratio in the modeling fracture. Filtration test show that this new sinking agent can form a barrier, which can strongly plug fracturing fluid. When the closure pressure range is in the range of 6.9 MPa–69.0 MPa, conductivity of the barrier formed by this new sinking agent is at a low level of 2.9 μm2 cm to 1.5 μm2 cm. With a given sand ratio and carrying-fluid concentration, the barrier formed in the fracture by the new sinking agent is more uniform than the other sinking agents. Based on the field application in a low-permeability/bottom-water reservoir, the usage of this new sinking agent increases oil recovery but decreases the water cut compared to other sinking agents. Highlights • A new sinking agent is introduced in hydraulic fracturing for the low-permeability/bottom-water reservoirs for water control. • Experimental measurements are conducted to evaluate the performance of this new agent. • Field application validates the superiority of this new sinking agent for water control. [ABSTRACT FROM AUTHOR]

Abstract When the oil shale reservoir completes acid fracturing, the back-flow of fracturing fluid program is needed. In this paper, a three-dimensional model is established and the finite element analysis software is used to simulate the feasibility of gas lift back fracturing fluid in Fuyu oil shale formation after acid fracturing. The results show that when the injection pressure of FK-1 well is 8.5 MPa, the fracturing fluid can be effectively displaced. Fracturing fluid is discharged along the fracture into FK-2 well, and a few fracturing fluids overflow the pyrolysis zone along the direction of oil shale bedding. Then the experiment is carried out to verify the accuracy of numerical simulation. What's more, it is also verified that the connectivity of oil shale reservoir meets the needs of oil shale in-situ pyrolysis process. Graphical abstract Image 1 Highlights • Flow-solid coupling analysis simulated the back-flow fracturing fluid experiment. • Back-flow fracturing fluid by high pressure nitrogen displacement was carried out. • Pressure oscillation for formation connectivity test is proposed. [ABSTRACT FROM AUTHOR]

Abstract In the fracturing pipeline, the contraction-expansion pipe structure is various. Accurate calculation of pressure loss can provide a theoretical support for the design of high sand ratio fracturing process parameter and tools selection. In this paper, the building block approach is used to describe the general framework for calculating the pressure loss of water in contraction-expansion pipe [ D 1 ≠ D 2 、 L d /(D 1 /2 + D 2 /2)＜2.00] and expansion-contraction pipe (d 1 ≠ d 2 、 L D / D ＜3.75). The drag ratio method was used to describe the pressure loss of the fracturing fluid based on the pressure loss of water in the contraction-expansion pipe and the expansion-contraction pipe. Finally, the calculation methods for the pressure loss of water and fracturing fluid were described. The data from the experimental test showed that the relative error was less than 15%. The experimental study of water in the contraction-expansion pipe showed that the pressure loss was positively correlated with the flow rate, but it was negatively correlated with the ratio of inlet-outlet diameter and the ratio of flow path length. And for the expansion-contraction pipe, pressure loss was positively correlated with the flow rate and ratio of flow path length. When the ratio of flow path length was close to 3.75, the ratio of inlet-outlet diameter was positively correlated with the pressure loss, and when the ratio of flow path length was close to 0.05, the ratio of inlet-outlet diameter was negatively correlated with the pressure loss. Analysis of fracturing fluid in contraction-expansion pipe and expansion-contraction pipe showed that the flow rate, proppant concentration and thickener concentration were positively correlated with pressure loss, and the drag rate of fracturing fluid reached 72%. Graphical abstract Image 1 Highlights • The pressure loss of fluid in variable diameter pipe is studied experimentally. • The object of fluid research are water and fracturing fluid. • Building block approach was used to describe the pressure loss of water. • Drag ratio method was used to describe the pressure loss of fracturing fluid. • The influence of the structural parameters of pipe on pressure loss is analyzed. [ABSTRACT FROM AUTHOR]

Abstract Tight sandstone reservoirs with low porosity and permeability are always vulnerable to damage due to drilling and fracturing fluids, which significantly impedes hydrocarbon production. Therefore, exploring damage evaluation methods has been an undeniable demand of formation protection and efficient development. However, the common steady-state core flow method is time-consuming and inaccurate for evaluating permeability damage in tight low permeability reservoirs. Aiming at this problem, this paper introduced pressure transmission test (PTT), a time-saving and accurate method, to quantitatively evaluate the core permeability damage degree from macroscopic perspective. Furthermore, nuclear magnetic resonance (NMR) was also used to analyze the damage mechanisms of fracturing fluids from microscopic perspective. In the fracturing fluids damage experiments, the results of PTT show that the ultimate damage degree of fracturing fluids is approximately 40%, of which water-sensitivity, water-block, and solid-phase are approximately 10%, 12% and 16%, respectively. With the technique of NMR, the damage mechanisms due to fracturing fluids are also investigated. In the drilling and fracturing fluids damage experiments, the results of PTT show that the drilling fluids cause the major damage. In the experiments of acidizing treatment, the chelating acid shows excellent properties in reliving core permeability damage caused by drilling and fracturing fluids. This study provides a new idea for evaluating permeability damage in low permeability reservoirs, such as shale, tight sandstone reservoirs, bedrock reservoirs, and so on. Highlights • Pressure transmission test was introduced to evaluate damage degree of injected fluids. • The damage mechanism of fracturing fluids was revealed. • The chelating acid shows excellent properties to relieve formation damage. [ABSTRACT FROM AUTHOR]

Abstract Hydraulic fracturing using freshwater as fracturing fluid is regularly employed in commercial shale gas or oil production. Many problems are brought by the fracturing fluid of water, such as water shortages, swelling of clay mineral, and the pollution of flow-back water. Replacement of water by supercritical CO 2 (SC CO 2) in the hydraulic fracturing treatment of shale reservoir has meaningful potential for the improvement of gas production. Hydraulic fracturing experiments, under different injection rate and stress state, were carried out for studying the SC-CO 2 fracturing of shale considering anisotropy effects. Anisotropy of shale has a significant impact on the mechanical behavior and fracture propagation of shale in the experiment. There shows a downward tendency for breakdown pressure with the increase of bedding plane angle in general. Higher injection rate can lead to the higher breakdown pressure, while higher deviator stress can lead to the lower breakdown pressure instead. In addition, three patterns of fracture propagation can be observed in the experiment, relative to the bedding structures of shale specimen, including propagating along, propagating across and arresting. The maximum values of fracture width during experiment in shale with different bedding plane angle ranges from 0.29 mm to 1.05 mm, while the final fracture width after the fracturing experiment is kept within the range of 0.01 mm–0.04 mm under the injection rate of 0.3 ml/s. Highlights • Experimental study on the supercritical CO 2 fracturing was carried out in the lab. • Some impact factors on the supercritical CO 2 fracturing of shale were studied. • The fracture propagation pattern relative to the bedding structure was summarized. • Evolution of the fracture width during the fracturing process was discussed. [ABSTRACT FROM AUTHOR]

Abstract Recent advances in hydraulic fracturing, in conjunction with horizontal drilling, have enabled large-scale extraction of natural gas and oil from shale formations. Despite its advances and enormous economic benefits, opportunities remain to increase hydraulic fracturing efficiency and minimize potential environmental impacts. This review specifically examines three key themes associated with development and utilization of hydraulic fracturing fluids: 1) characteristics and behavior of fracturing fluids, 2) understanding and predicting migration and fate of fracturing fluids, 3) technologies to reduce environmental impact of fracturing fluids. The paper discusses key and new techniques and findings on rheology of hydrogel-based fluids, high fidelity simulation of propagation transport, potential environmental impacts, geosynthetics in mitigating contamination, and greener fracturing fluids. It is indicated that future development relies on advances in understanding of physical processes, modeling capabilities, and monitoring techniques. [ABSTRACT FROM AUTHOR]

Abstract Supercritical CO 2 (SC-CO 2), as a non-aqueous material of fracturing fluid, receives widely attention in the development of unconventional reservoirs. In this study, permeability regain (K rg) was introduced to characterize the permeability alteration on tight cores by SC-CO 2 fracturing fluid. Meanwhile, scanning electron microscope (SEM), microscope system, nuclear magnetic resonance (NMR) were used to reveal the mechanisms of permeability alteration at different scales. The results showed that the composition of SC-CO 2 fracturing fluid, fluid filter loss, and reservoir permeability were all responsible for permeability alteration. With the increasing thickener contents and filter loss of fracturing fluid, core permeability regains turned to be declined. Comparatively, tight cores which consist of more micro-nanometer sized pores were more likely to receive more formation damage of permeability, as well. The retention of thickener in microchannels (micro pores) were confirmed to be the main mechanisms on permeability alteration. Highlights • A novel, systematic method of permeability alteration measurement after SC-CO 2 fracturing fluid treatment was built. • The effect and degree of various factors for permeability alteration in different cases were evaluated. • The main mechanism of permeability alteration was analyzed by use of SEM, inverted microscope and NMR. • The adsorption and trapping micromorphology of SC-CO2 fracturing fluid in cores were conducted at different scales. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is an effective and increasingly popular method of improving the permeability of coal deposits. However, fracturing fluids specifically designed for coal deposits are required, as the properties of the fracturing fluid can affect the permeability improvement. A numerical model and rheological tests were used to determine the optimum viscosity and composition of fracturing fluid for underground fracturing. The effect of this optimized viscoelastic surfactant fracturing fluid on coal porosity, gas adsorption and permeability were experimentally investigated and compared with water as a fracturing fluid. Results showed that the viscoelastic surfactant fracturing fluid increased coal pore volume and surface area by 33.9% and 30.6% respectively, compared with samples processed with water. Adsorption and permeability tests on the coal samples processed with viscoelastic surfactant fracturing fluid and water showed that the adsorption capacity was reduced by 22.4% when using viscoelastic fracturing fluid, while the permeability increased by 178%. Using viscoelastic surfactant fracturing fluid can increase the fracturing area and promote gas desorption and seepage, thus improving gas extraction. The results of this study demonstrate the potential for applying of viscoelastic surfactant fracturing fluid in underground fracturing in coal mines. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing creates a complex fracture network that makes the oil production from low-permeability reservoirs economical. However, significant amount of water is likely lost into the rock matrix during hydraulic fracturing. This can cause formation damage due to multiphase flow, thus hindering the oil production rate. Surfactants can alter rock wettability and/or reduce oil-water interfacial tension (IFT), and it has been proposed to be used to mitigate such water blockage and enhance oil recovery. Among different approaches of using surfactants, forming liquid nanofluid (LNF) can minimize the adsorption of surfactants on rock surface, and it is likely to be one of the best options for low-permeability rocks with extensive surface area. In this study, the key properties of a well-screened LNF are evaluated, and then compared with a commercial flowback surfactant (CFS) that is widely used in the field. Pressure transmission test is further applied, which can determine the change of rock permeability due to different fluids and the potential formation damage due to multiphase flow. A systematic evaluation method is thus established to screen fracturing fluid additives to enhance oil production from low-permeability reservoirs both effectively and efficiently. [ABSTRACT FROM AUTHOR]

Fluvial sediments with multi-scale channels are difficult to model using classical two-point statistical methods, e.g. sequential indicator simulation (SIS) or object-based modelling (ObjM). Multiple-point statistics (MPS) has been used to generate facies, fracture and porosity distributions based on pattern statistics derived from training datasets. However, the ability of these three methods to reproduce channel geometry and continuity is not clear, especially when using differently spaced conditional data. This paper presents a case study to compare the application of these three methods in reproducing channels from a section of Amazon River based on two differently spaced conditional data sets. Results show that: the reproduction accuracy is similar between MPS and SIS; MPS provides the most connected channel facies (or most channel continuity) as compared to SIS and ObjM; and using a hand-drawn facies based on the sampling points yield a similar accuracy to that achieved by using the reality facies distribution as the training image. Finally, we conclude that the application of MPS does not significantly increase the reproduction accuracy when compared to SIS channel models; however, MPS can generate realistic models with respect to channel geometry and continuity. [ABSTRACT FROM AUTHOR]

Positive Displacement Motor (PDM) has been used extensively in directional and horizontal drilling operations. To the best of our knowledge, there is no reliable analytical model to predict the performance of PDMs. Based on motor geometry; each PDM has its own unique performance that is experimentally obtained by manufacturers using water as a testing fluid. These experiments are not only costly and time-consuming, but also with conditions that do not represent the actual down-hole conditions. The key to improve the prediction of motor performance is to, accurately; determine the flowing cross-sectional area of PDM. This paper uses Nguyen et al. (2014) model for calculating flow area of a multi-lobe progressing cavity pump, in addition to two developed analytical models for predicting the actual performance of a multi-lobe PDM. A sensitivity analysis was performed to optimize motor geometry to maximize motor torque. The developed models were validated using experimental data from a single 1:2-lobe and multi 2:3-lobe PDMs. The results revealed that when the stator lobe number is greater than five, torque is maximized if the dimensionless motor geometry is zero. The flowing cross-sectional area is reduced when the stator lobe number is higher than four lobes. However, the flow rate is always higher when the stator lobe number is increased. The results also showed that it is not recommended designing a PDM which has the stator lobe greater than twelve. Furthermore, model validation showed that the proposed model predicts the actual multi-lobe PDM performance with average percent error of less than 6% when differential pressure across the motor is 300 psi or less. The results of this study are not only important for manufacturers to optimize PDM design, but also for operators to improve the performance and efficiency of PDMs. [ABSTRACT FROM AUTHOR]

Casing annulus pressure build-up owing to fluid thermal expansion in sealed annuli severely threaten the casing safety and wellbore integrity of deepwater wells. To mitigate the annular pressure with stronger effect and lower cost, a new type of syntactic foam with high compression ratio, which consists of hollow glass microspheres and a resin matrix system, was developed in this study. It can provide extra space for the annular fluid to expand when the annular pressure exceeds the specific foam crush pressure, allowing the foam to collapse and consequently, mitigate the annular pressure. The foam compression behavior is divided into three stages according to a hydrostatic compression test, and the annular pressure is mainly influenced by the microspheres volume and temperature. To optimize the parameters of the compressible foam, a novel model considering fluid thermal expansion, casing elastic deformation, and foam compression behavior in multi-annuli is established. The results indicate that the compressible foam can reduce the trapped annular pressure effectively and permanently. In a case study well, the annular pressure no longer exceeds the maximum acceptable annular pressure in each annulus with optimized design of the foam wraps and a suitable number of installed foam casing joints. [ABSTRACT FROM AUTHOR]

The discrete fracture-matrix model (DFM) technique has contributed to the rapid development of fracture modeling. In terms of vertical well modeling, however, the current well models fail to handle the field-scale DFM utilization. In this study, a pseudo inner-boundary model is presented tailored to this problem. Specifically, the modeling methodology consists of mesh generation and transmissibility evaluation. Regarding the mesh generation, the model handles the 2-D triangular-gridded matrix and 1-D edge-gridded fracture. The strict geometric analogy to generate triangles for the wellbore is abandoned, instead, the wellbore is approximated by a source/sink point and returns to a circular geometry when evaluating the transmissibility. The treatment sheds the limitation of triangle size and proves to boost the generation efficiency. Regarding the transmissibility evaluation, the derived formulations apply the radial/linear approximation for flow in matrix/fracture well-gridblock, and various conditions are considered, including gridblock geometry (triangle and rectangle), flow state (steady-state, unsteady-state and pseudosteady-state) and well completion (fully penetrating well and partially penetrating well). In addition, the compatibility with the star-delta transformation is discussed. By refining the well-gridblock into several sub-triangles, the formulations could be rapidly implemented to non-triangle-based DFM (e.g. PEBI, Cartesian). The model performance is demonstrated in eight validation cases. The model is shown to provide results in close agreement with those of reference in cases where the direct comparisons are performed. [ABSTRACT FROM AUTHOR]

Supercritical carbon dioxide (SCCO 2 ) fracturing fluid is an excellent application in CO 2 re-use. It has many advantages than water-based fracturing fluids. However, the low viscosity hinders its application in unconventional oil and gas reservoirs. Therefore, we tried to improve the property of SCCO 2 fracturing fluid by increasing the viscosity. A thickened SCCO 2 fracturing fluid was constructed and the fracturing property of the fracturing fluid was investigated. The fracturing fluid consisted of toluene (cosolvent), polydimethyl silicone (thickener) and SCCO 2 . In SCCO 2 , toluene and polydimethyl silicone obtain low miscible pressure at 42 °C. In addition, the constructed fracturing fluid system obtains higher viscosity value (as high as 1.5 mPa·s), which can be 40 times high than the viscosity of pure SCCO 2 at 42 °C and 20 MPa. These features match the viscosity requirement as a fracturing fluid. Molecular dynamics (MD) simulations were carried out to study the solubility parameter of the fracturing fluid system in molecular level. These MD simulation results show that, as a cosolvent, toluene helps polydimethyl silicon dissolve in SCCO 2 , which is consistent with laboratory experiment results. Moreover, the studied fracturing fluid obtains good properties as a fracturing fluid in terms of high proppant carrying capability, low fluid leakoff coefficient, and low formation damage rate. [ABSTRACT FROM AUTHOR]

Acidizing of carbonate oil-wet rocks saturated with oil and saline formation water is subjected failure in some cases due to acid-induced damage such as sludge and emulsion formations. This condition may also lead to mineral precipitation, oil film barrier between acid and rock and diversion chemical malfunctions. Therefore, pre-flush process has been proposed as one of the most efficient stage for oil-wells matrix acidizing to reduce these challenges significantly. Besides, the pre-flush stage would result in more clean rock as the reservoir fluids are pushed back from the near wellbore regions, restoring rock wettability to more water wet state, preventing direct acid-oil contact and cooling rock surface to control acid-rock reaction at high temperature reservoir. This laboratory work is designed to study the effectiveness of three different pre-flush fluids and assess their ability in reducing interfacial tension (IFT) to displace original reservoir fluids around the wellbore as well as changing the rock wettability to increase rock dissolution rate. The results showed that a 0.5%wt of C16TAB aqueous solution (cationic surfactant additive) has passed successfully the pre-flush optimization criteria which can be utilized as pre-flush fluid of the carbonate oil-wet acidizing. It was shown that the wettability and IFT were changed quickly as it is requested for the pre-flush stage. The contact angle was decreased from 172° to 33° in two hours period and the IFT was reduced from 8.9 to 0.62 (dyne/cm) at reservoir condition (P = 4000 psia, T = 85 °C). In addition, the dissolution rate of dolomite rock from an Iranian oil reservoir at three different states of oil-wet, water-wet and pre-flush treated with 15% HCl was measured and compared. The measured dissolution rate of initially water-wet rock was measured to be 1 × 10 −4  mol/cm 2 .s which is the same as the dissolution rate measured for C16TAB treated oil wet rock. This confirms the suitable wettability alteration through C16TAB pre-flush. [ABSTRACT FROM AUTHOR]

As a new clear and efficient fracturing fluid, supercritical carbon dioxide (SC-CO 2 ) has many advantages in the development of unconventional oil and gas resources, such as no harm to the reservoir, improving the reservoir permeability and fluid flow resistance, quickly completely flowing back after fracturing. Based on the principle of suspension energy balance, an equilibrium flow rate model of proppant-carrying flow of SC-CO 2 is derived, and calculation errors are 3.32% and 4.54%, respectively, compared with equilibrium flow rates obtained from experiments under different density and particle sizes. By considering the change of fluid internal energy and flow work, filtration characteristics, physical parameters, and SC-CO 2 –rock adsorption in the SC-CO 2 fracturing process, a proppant-carrying flow calculation model of the SC-CO 2 fracturing fluid is established based on temperature–pressure field coupling, fracture and filtration zone coupling, and SC-CO 2 fluid and proppant coupling. In the experiment, the heights of nine groups of proppant embankments were measured, and the average model prediction error value is 3.43%. SC-CO 2 has a similar proppant-carrying capacity to that of clear water under the high Reynolds number condition. Based on the proppant-embankment prediction model of SC-CO 2 fracturing, through analyzing proppant-carrying characteristics of the SC-CO 2 fracturing fluid, the proppant concentration distribution and proppant embankment section are obtained at different fracturing times. According to the calculation, as the fracturing fluid pumping rate increases, proppant density and proppant particle size will decrease, the viscosity of the SC-CO 2 fracturing fluid system will increase, and proppant accumulation height can be reduced over a small range, while proppant accumulation length will experience a greater increase along the fracture length direction. During field operation of SC-CO 2 fracturing, the proppant pumping process should be optimized according to the proppant embankment section and proppant concentration should be choose increased in small steps to meet fracture propping requirements. [ABSTRACT FROM AUTHOR]

The residual opening of fluid-driven fractures is conditioned by proppant distribution and has a significant impact on fracture conductivity - a key parameter to determine fluid production rate and well performance. A 2D model follows the evolution of the residual aperture profile and conductivity of fractures partially/fully filled with proppant packs. The model accommodates the mechanical response of proppant packs in response to closure of arbitrarily rough fractures and the evolution of proppant embedment. The numerical model is validated against existing models and an analytic solution. Proppant may accumulate in a bank at the fracture base during slick water fracturing, and as hydraulic pressure is released, an arched zone forms at the top of the proppant bank as a result of partial closure of the overlaying unpropped fracture. The width and height of the arched zone decreases as the fluid pressure declines, and is further reduced where low concentrations of proppant fill the fracture or where the formation is highly compressible. This high-conductivity arch represents a preferential flow channel and significantly influences the distribution of fluid transport and overall fracture transmissivity. However, elevated compacting stresses and evolving proppant embedment at the top of the settled proppant bed reduce the aperture and diminish the effectiveness of this highly-conductive zone, with time. Two-dimensional analyses are performed on the fractures created by channel fracturing, showing that the open channels formed between proppant pillars dramatically improve fracture transmissivity if they are maintained throughout the lifetime of the fracture. However, for a fixed proppant pillar height, a large proppant pillar spacing results in the premature closure of the flow channels, while a small spacing narrows the existing channels. Such a model provides a rational means to design optimal distribution of the proppant pillars using deformation moduli of the host to control pillar deformation and flexural spans of the fracture wall. [ABSTRACT FROM AUTHOR]

During drilling the mud flows through the drill string and exits through the choke valve. The mud density range has as constraints: pore pressure (minimum limit) and fracture pressure (maximum limit). In fact, annulus bottomhole (downhole) pressure needs to be higher than pore pressure, in order to prevent kick, and smaller than fracture pressure, for avoiding mud loss and formation damage. Experimental and simulation studies were implemented in order build a monitoring – diagnosing tool working together with a decision making routine based on an adaptive control scheme that employs gain scheduling. An experimental unit was built, presenting the most important characteristics of the drilling process. The transient nature of annulus bottomhole pressure is due to the process inherent disturbances: rheology, rate of penetration (ROP), kick and mud loss, which were all implemented at the experimental unit. The major objective of the present paper is using the experimental plant and a phenomenological model for implementing real time process automation, in order to assure drilling inside operational window, using in line measurements for flow and density disturbances under circulation loss and kick scenarios. [ABSTRACT FROM AUTHOR]

Commercial development of coalbed methane (CBM) in China has lasted for a decade. However, in 2015 annual CBM production in China was less than 5 Bcm and lagged far behind those in US (35 Bcm) and Australia (18 Bcm). In this paper, we review the published literature to determine the engineering challenges and opportunities of CBM production in China. Our review has identified seven major engineering challenges to CBM development in China. They are low cleat permeability and underpressured formation pressure of high-rank coals, ductility of coal seams, suboptimal fracturing fluids, formation damage during drilling, borehole instability in horizontal wells, frequent pump failures during production, and inadequate produced water treatment methods. Each of these challenges provides an opportunity for improvement. We propose a refocus on low-rank coals which have higher permeability. Other opportunities include development of better hydraulic fracturing fluids, non-formation damaging drilling fluids, use of geomechanics to understand borehole instability, optimization of the artificial lift methods and more robust and environmentally friendly produced water treatment methods. [ABSTRACT FROM AUTHOR]

In light of the high treatment costs for massive amounts of fracturing flow-back fluid and its harmfulness to the environment, a novel method of recycled fracturing flow-back fluid (RFFF) to enhance oil recovery by spontaneous imbibition is proposed in this study; this method does not allow the flow-back fluid back to the ground, thereby preventing negative impacts. The wettability alteration and interfacial tension (IFT) can effectively strengthen the spontaneous imbibition to enhance oil recovery in low-permeability sandstone reservoirs. This study combines the effects of wettability alteration and IFT with the use of the RFFF, which is composed of viscoelastic surfactants, on the spontaneous imbibition in low-permeability outcrop cores. Contact angle (CA) experiments, IFT experiments, and spontaneous imbibition experiments are conducted. The CA and IFT experimental results showed that the RFFF solutions changed the wettability of the core surface from oil-wet to water-wet and easily reduced the IFT between the crude oil and the RFFF solution to 10 −3 -10 −2  mN/m, which improved the oil recovery by changing the capillary forces. The spontaneous imbibition results showed that the RFFF solutions at concentrations of 0.03–0.10 wt% resulted in a higher imbibition recovery due to the synergistic effect of the wettability alteration and the IFT, which was attributed to the wedge film structure and the spreading force. It can be concluded that the use of the RFFF has the potential to further enhance oil recovery after fracturing the formation in low-permeability reservoirs without letting the fluid flow back to the ground. The proposed method is multi-functional and does not only improve the oil recovery by integrating fracturing and displacement methods but also reduces the costs of reservoir development and protects the environment. [ABSTRACT FROM AUTHOR]

The conventional hydraulic fracturing fails in the target oil/gas zone (remaining oil, closed reservoir, etc.) which is not located in the azimuth of maximum horizontal stress of available wellbores. The technology of directional propagation of hydraulic fracture guided by vertical multi-radial slim holes is innovatively developed. In order to verify this technology, lots of true triaxial hydraulic fracturing simulation experiments were carried out with artificial cores, aiming at investigating the influence of in-situ stress, fracturing fluid displacement, and azimuth, diameter, number, and spacing of radial slim holes on fracture propagation. The results show that directional propagation of hydraulic fractures guided by vertical multi-radial slim holes is feasible. Regardless of varied radial slim hole and in-situ stress parameters, hydraulic fracture always initiates in the heel of radial slim hole. For hydraulic fracturing assisted by single radial slim hole, smaller horizontal stress difference (3 MPa, σ H /σ h  = 1.25) and smaller radial slim hole azimuth (15°) may guide propagation of hydraulic fractures along radial slim hole, and larger horizontal stress difference (6 MPa, σ H /σ h  = 1.67) can sharply reduce guidance of radial slim hole. Affected by mutual interference from guidance of radial slim holes and controlling of horizontal in-situ stress, fractures tend to distort along fracture length and fracture height. For hydraulic fracturing assisted by vertical multi-radial slim holes, horizontal stress difference is one of key factors influencing the directional propagation effect of hydraulic fracture. Larger horizontal in-situ stress difference (>6 MPa, σ H /σ h  > 1.67) hardly results in directional propagation of hydraulic fracture along radial slim hole row, and creates bigger diversion angle of fracture, and larger azimuth (>45°) of radial slim hole row reduces the guidance strength, resulting small fracture diversion radius. In conditions of larger angle between target zone and maximum horizontal stress, and requirement of large azimuth of radial slim hole row, the effective hydraulic fracture propagation along radial slim holes and ideal fracture height will be achieved through human intervention, e.g. increment of the number and diameter of radial slim holes, reduction of radial slim holes spacing, increment of fracturing fluid displacement, etc. The simulation results provide methods for designing directional propagation of hydraulic fractures guided by vertical multi-radial slim holes. [ABSTRACT FROM AUTHOR]

Supercritical carbon dioxide (SC-CO 2 ) used as a fracturing fluid in the shale fracturing stimulation is a promising technology as it can save much water and have some particular properties, such as low surface tension, large diffusion coefficient, strong permeable ability and adsorption capacity in shale. In previous studies, SC-CO 2 fracturing presents great advantages in marine shale, granite and tuff. In this work, continental shale with interbeds from the Ordos Basin, China was used to conduct SC-CO 2 fracturing experiments under the different stress conditions. Based on the observation of visible fractures before and after experiments, the fractures on the surface mainly propagate along natural fractures, bedding planes and interbeds, where crossing beddings and interbeds can also be observed. Besides, according to visualization and quantification of the main fractures and the main fracture surfaces by electronic microscope and three-dimensional scanner, with the increase in the stress difference, the main fracture can easily cross shale beddings and interbeds, and partial vertical fractures are formed, so tortuosity of the main fracture and roughness of the main fracture surface tend to increase. Furthermore, four main types of interactions between the main fracture and the fracture branch are obtained and the number of the fracture branches induced by the SC-CO 2 fracturing is generally larger than that induced by the water fracturing. Meanwhile, compared with the water fracturing, it is implied that the breakdown pressure of SC-CO 2 is generally lower, and its tortuosity of the main fracture and roughness of the main fracture surface tend to be higher under the same experimental conditions. Therefore, more curved and wavelike fractures with more branches can be generated in the continental shale SC-CO 2 fracturing. [ABSTRACT FROM AUTHOR]

Different laboratory experimental setups with slotted disks, simulating fractures’ apertures, have been used extensively to formulate effective loss circulation materials (LCM) recipes. The amount of fluid loss and sealing pressure have been used as the evaluation criteria. The question still remains is how valuable these tests are when LCM fluids are circulated in the wellbore to stop losses. The main objective of this work is to study the effect of the annular fluid flow on building an LCM bridge at the fracture aperture. To address the objective, a fluid loss apparatus has been developed to mimic wellbore circulation. Tapered slotted disks were placed upward in a cylinder filled with drilling fluid and LCM additives. Drilling fluid is pumped at the bottom of the cylinder and the wellbore circulation is simulated through the use of stirring paddle. Previously reported effective LCM recipes have been retested conventionally, no simulated circulation, and under simulated circulation condition (S circ ) with varying pump flow rates and tapered slotted disk sizes. A new term, sealing effectiveness ratio (SER), is introduced to effectively evaluate the sealing integrity of the LCM recipes at the S circ . The results showed when stirring the sample, a higher fluid loss was required before the sample sealed and the maximum sealing pressure ( P max ) was lower than sealing pressures reported from conventional tests. Different LCM recipes required a different minimum flow rate for a seal to initiate at the S circ . Increasing the flow rate improved the sealing effectiveness ratios of all LCM recipes. At high flow rates some recipes gave very similar P max as conventional tests while others lost more than 35% of their strength. At a given flow rate with larger opening size slot, the effect of S circ was amplified as higher fluid loss was required to initiate a seal and a lower sealing effectiveness ratio was recorded. The most significant new finding is that LCM with lower specific gravity was less prone to the S circ making them better preventive approach candidates. [ABSTRACT FROM AUTHOR]

This study outlines a workflow that combines reservoir characterization and decline curve-based production analysis with a physics-based drainage model that quantifies where fluid is drained from, based on the fracture treatment architecture. Decline curve analysis, applied to production data from four multi-fracked wells in the Eagle Ford formation (Brazos County, East Texas), provides forecasts for the estimated ultimate recovery (EUR). About 50% of EUR is realized in the first 1000 days (∼3 years) of the well-life. The drainage model shows where in the reservoir the produced fluid is actually drained from, based on the estimated reservoir parameters. This study includes several fundamental assessments of factors that may impact any drainage model, such as (1) the pressure front propagation time responsible for the depth of investigation, (2) pressure effects due to up-scaling of fracture patterns into a reduced number of fractures, and (3) interaction of fluid velocity patterns with pressure depletion zones. The drainage model for the Eagle Ford wells in our case study suggests that the first generation of hydraulic fractures recovers less than 1% of the original oil in place. With recovery factors so low, a repetitive schedule of periodic refracking the wells - provided the first refracks prove successful - is highly recommended. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is responsible for remarkable production from shale and tight formations, albeit at the cost of significant water usage. The flow dynamics of oil and fracturing fluid in nanopores remains largely uncharacterized, in part due to the challenge of conducting experiments at nanoscales. In this paper, we demonstrate a nanofluidic-based approach to visualize the fluid displacement during hydraulic fracturing. Nanoporous silicon-glass chips with circular and square grain shapes and identical depth of 175 nm were fabricated using reactive-ion etching (RIE) and anodic bonding. Leveraging the inherent fluorescence property of the oil, the fluorescence microscopy was used to record the dynamics of the fluid displacement inside the chip. Performance of three different fracturing fluids - deionized water, potassium chloride (KCl) solution, and slick water - were evaluated based on the volumetric infiltration in the nanoporous network, entrapment of fracturing fluid in the porous media, and total production during drawdown. The KCl solution had the highest infiltration rate (fill factor of 0.68) and the lowest entrapment factor (0.39), resulting in the highest fracturing fluid recovery representing 43% in the square grain geometry with similar results for circular grains. With the fast quantification and ease of operation here, the nanofluidic approach enables a rapid screening of different fracturing fluids to inform shale oil operators. [ABSTRACT FROM AUTHOR]

In the past several decades, Gemini viscoelastic surfactant has been applied for many cases due to its specific properties, including clean fracturing fluid. As we know that counter-ions can greatly promote the micelle aggregation of VES and show important effect on its heat resistance. Potassium chloride, as a normal additive for fracturing fluids to control the clay swelling, was investigated as such counter-ions in the context. Thus, a clean fracturing fluid with good heat resistance could be obtained by studying the viscosity reduction of the fluid prepared from a novel Gemini VES. The results of molecular structure characterization showed that potassium chloride has no effect on the surfactant molecular structure in rheological tests at high temperature. Based on the rheological tests, it can be concluded that the viscosity reduction at the test conditions is mainly of the micelle dissociation. Analysis results, such as microstructure comparison and the dynamic light scattering, suggested that potassium chloride can facilitate the micelles aggregation and entanglement, especially making the micelles tighter. In this way, the fluid could keep higher viscoelasticity at higher temperature and certain shear rate. Based on this mechanism, an improved VES fracturing fluid could be achieved via iterative formation adjustment, whose final viscosity could be maintained about 40 mPa s at 160 °C during 120 min. [ABSTRACT FROM AUTHOR]

Relative to water-based fluids, non-aqueous fracturing fluids have the potential to increase production, reduce water requirements, and to minimize environmental impacts. Since the viscosity of supercritical CO 2 is one-tenth that of water, its density is close to that of water, and is capable of promoting sorptive rejection of methane, it is an attractive substitute for water in the extraction of shale gas and coalbed methane. The following defines a geomechanical model accommodating the interaction of fluid flow, adsorption-induced swelling stress, solid deformation and damage to quantify rock-gas interactions during supercritical CO 2 fracturing for shale gas production. The architecture of the shale is accommodated that includes both pore- and micro-crack-based porosity. According to the microcrack model representing shales with low porosity, both analytical and numerical results show that the effective stress coefficient is much smaller than unity. We analyze the potential advantages of fracturing using supercritical CO 2 including enhanced fracturing and fracture propagation, increased desorption of methane adsorbed in organic-rich portions of the shale and the potential for partial carbon sequestration. Rock-gas interactions include both the linear poroelastic response and the chemo-mechanical interaction due to sorption. Simulation results demonstrate that supercritical CO 2 fracturing indeed has a lower fracture initiation pressure and a significantly lower breakdown pressure, as observed in experiments, and that fractures with greater complexity than those developed with liquid CO 2 and water fracturing result. With increasing dynamic viscosity of the fracturing fluids, the predicted breakdown pressure also increases, consistent with experimental observations. [ABSTRACT FROM AUTHOR]

Slickwater fracturing has historically utilized freshwater as a base fluid and Friction Reducer (FR) as a main additive to reduce the friction pressures in the wellbore and within the fractures. This technology is getting challenging because of the limited sources of freshwater, the increased flowback fluid disposal costs, and stricter disposal regulations. The oil and gas industry has been trying to optimize the reuse of slickwater fracturing flowback fluids to help reduce the use of freshwater. The flowback contains mainly water, salts from formation water, and chemicals that were introduced from the hydraulic fracturing. The main objective of this study is to experimentally investigate effects of salinity on the performance of FRs for the purpose of reusing the flowback. The Hydraulic Testing Facility was used to perform hydraulic tests to investigate the effects of salinity on the performance of FRs. Three commercial FRs, namely anionic Friction Reducer A (FR-A), anionic Friction Reducer B (FR-B), and cationic Friction Reducer C (FR-C), were used to conduct the tests. The concentration of the FRs was varied from 0.5 to 1.2 liters/m 3 of water (0.5–1.2 gallons per thousand gallons of water). Sodium Chloride and Calcium Chloride at different concentrations were added to the solution to study the salinity effects. In addition, multiple rheological tests were executed to understand the effects of salinity on the rheological properties of slickwater. The results revealed that the anionic FR-B performs better than the anionic FR-A in fresh water. The percent friction reduction of FR-B and FR-A at 0.478 g/L (4 pptg) in fresh water were about 60% and 40%, respectively. In addition, the performance of FR-B is less sensitive to salts than that of FR-A. Therefore, It is recommended to add 0.478 g/L (4-pptg) of FR-B directly into the flowback, which has the total dissolved solid values of 100000 mg/L or less without the need of pretreatment to achieve the percent friction reduction of 40% or higher. Cationic FR-C performed the best when compared with anionic FR-A and FRB at high salinity, e.g. 200000-mg/L total dissolved solid. Under the testing conditions, a conservative conclusion may be drawn that cationic FRs may perform better with the presence of salts than that of anionic FRs. [ABSTRACT FROM AUTHOR]

The filtration characteristics of drilling fluids were evaluated by dynamic filtration under cross flow geometry. Crossflow (tangential flow) filtration by using a rotating cylinder geometry occurs when the mud is being circulated radially by inner rotating cylinder and permeates tangentially through the outer wall filter media. Dynamic filtration tests under cross flow represent more realistic conditions compared to static tests. The growth of the filter cake and filtrate flow are controlled by the blocking and erosive action of the mud stream. Dynamic HPHT ® Filtration System Model 90 which operates at high temperature and high pressure, manufactured by Fann Instrument Company™ is the most commonly used device to evaluate fluid loss and filtration characteristics of drilling fluids. However, according to its equipment manual, there are no standard methods for interpreting the dynamic filtration data. Here, the fluid loss data of drilling mud formulations were modelled based on the kinetics of filtration and plugging of through filtration media by drilling muds. The total volume loss, V as a function of time under crossflow filtration was expressed by writing ordinary differential equation of the flux which decreases due to pore plugging and cake forming and increases due to cake erosion. The differential equation was solved and the experimental data were analyzed by stating spurt loss volume as an initial value. The solution of derived differential equation which we called as Boluk-Balavi dynamic filtration equation expressed the dynamic filtration data of muds perfectly well. The fittings of experimental results to the equation gave us the direct evaluation of spurt loss volume, initial rate of fluid volume loss (flux), filter blocking and cake erosion. [ABSTRACT FROM AUTHOR]

Sustained casing pressure (SCP) is one of the most common and costly problems in the oil and gas industry, which results in various unfavorable effects in the economy and catastrophic consequences. The development of micro-annulus and micro-cracks within the cement sheath causes the need to develop a unique self-healing spacer fluid to enhance the integrity of cement sheath. This study aims to investigate a novel self-healing spacer fluid that provides a long-term zonal isolation to mitigate SCP problems during well cementing or production operations. Micro-annulus or micro-crack simulation experiments were conducted on artificial cement sheath samples under various confining pressures to investigate the self-healing capability of the novel self-healing spacer fluid. Post-evaluation methods, such as self-healing test and computed tomography scanner, as well as scanning electron microscopy, were used to investigate the effect of the self-healing spacer fluid on the properties of the original cement slurry and repair effectiveness. The self-healing capability of the novel self-healing spacer fluid was assessed based on the conducted experiments and post-evaluation analyses. The effect of the self-healing spacer fluid on the cement slurry properties and casing corrosion was also analyzed. Experiment results indicated that the novel self-healing spacer fluid could penetrate into the micro-cracks or micro-annulus within the cement sheath to activate the hydration reaction of the non-hydrated cement, thereby producing a hydrated calcium silicate gel (C–S–H or C–A–H) that could strengthen the main body for the damaged zone. The experiment results also indicated that self-healing spacers had a higher displacement efficiency than common spacers in improving the interface bond strength between the casing and cement sheath. Moreover, the self-healing spacers had a slight influence on the cement slurry properties and the ability to resist casing corrosion. Thus, the self-healing technology is safe and cost-effective for curing the SCP problem. [ABSTRACT FROM AUTHOR]

The use of fresh water as a fracturing fluid has limitations such as limited water availability in arid areas and negative impacts of water on oil and gas production in formations with high clay content. Alternatives to water for well fracturing include tailored energetic materials such as novel explosives. High energy gas fracturing (HEGF) creates radial fractures with fracture-orientations independent of formation stress anisotropy and heterogeneity. This eliminates the requirement of in-situ stress orientation for designing multi-hydraulic water-fracturing horizontal wells. Assuming uniformly distributed radial fractures around wellbore, an analytical well productivity model was derived in this study to predict productivity of HEGF-completed oil wells under pseudo steady state flow condition. Field case studies and sensitivity analyses were performed with the analytical model. Result of field case studies indicates that the analytical model over-predicts productivity of HEGF-completed wells by about 10%. Sensitivity analysis with the analytical model shows that the productivity of HEGF-completed wells reaches a maximum value at an optimal number of radial fractures around the wellbore. The productivity of the HEGF-completed wells increases non-linearly with fracture conductivity. But the benefit of increasing fracture conductivity levels out beyond fracture conductivity 2000 md-inch for the typical case investigated in this study. [ABSTRACT FROM AUTHOR]

A semi-analytical superposition model for analyzing pressure and rate data from wells where production characteristics were altered because of interference from nearby fracture operations is presented. In previous work (Thompson (2017)), specialized numerical simulations showed that these production changes could be explained by changes to the total fracture half-length and fracture permeability; in turn, these parameters alter the completion's linear flow parameter, k A , (which we loosely refer to here as the well's linear “flow capacity”) and “skin” pseudopressure drop (i.e., steady-state unit rate pseudopressure drop between the matrix and the wellbore). Superposition equations that govern fracture interference events under the assumption of linear flow to the fracture system are presented. The model is semi-analytical since no account is taken of variable gas compressibility effects in the superposition equation. Application of the technique allows quantification of interference-induced changes to both flow capacity, ( k A ) and skin pressure drop. By inverting the model, a method of predicting the well's production performance post-interference, given the changes to flow capacity and skin and a bottom-hole pressure production schedule, is developed. The predicted rate schedule is valid as long as the well remains in linear flow. The validity of the model is illustrated by applying it both to synthetic and a field production data. Based on the synthetic data, it is demonstrated that the superposition model can accurately describe changes to flow capacity and skin, and that the obtained model parameters can be used to reproduce the model rates given imposed bottom hole pressures. The method is applied to a field example where an interference event occurred, and demonstrates very good agreement between model predicted rates and observed field data. [ABSTRACT FROM AUTHOR]

The objective of this study is to investigate the effect of rock anisotropy on hydraulic fracture propagation. The coupled model of rock deformation and fluid flow is established to study hydraulic fracturing of orthotropic formation. Stress field is solved by using the extended finite element method with special tip enrichment functions for orthotropic formation. The coupling between stress field and pressure field is treated by Picard iterative procedure. The modified circumferential tensile stress criterion is used to determine fracture propagation, in which stress intensity factors are determined by an interaction integral method. Numerical results show that when fracture doesn't initiate from the direction of material axis with larger modulus, the fracture propagation direction would change and divert to the direction of material axis with larger modulus. And as Young's modulus ratio between two material axes increases, the phenomenon becomes more obvious. Moreover, shear modulus also enhances the diversion phenomenon of fracture propagation direction. However, the in-situ stress difference could weaken the effect of rock anisotropy. The results indicate that the propagation process of hydraulic fracture is influenced by comprehensive factors including material axis angle, Young’ modulus ratio, shear modulus and in-situ stress difference. [ABSTRACT FROM AUTHOR]

A BCG-CO 2 fracturing fluid system is especially suitable for shale gas stimulation because it has many advantages, including minimizing water consumption, reducing damage to the formation, and recovering more rapidly and efficiently. A major objective of this experimental study is to ascertain the convection heat-transfer characteristics of a BCG-CO 2 fracturing fluid system. A high-parameter foam fracturing fluid test system was adopted in this study. The measurement of convection heat transfer is based on the double-wall heat-transfer theory. Through experimental research, the correlations for BCG-CO 2 fracturing fluid convection heat transfer have been obtained under different foam qualities. The average error of the fitting formula for all experimental data is 10.7%. The results indicate that the convection heat-transfer coefficient decreases with increasing temperature, with an average decrease of about 10%. The convection heat-transfer coefficient shows a decreasing trend with increasing foam quality. There is a linear relationship between the convection heat-transfer coefficient and shear rate, and the shear rate has the most pronounced effect on convection heat-transfer characteristics. The results of this study can be used to calculate heat-transfer parameters to determine the temperature field of BCG-CO 2 fracturing fluid flow in fracturing design, and they are significant for the engineering application of BCG-CO 2 fracturing fluid. [ABSTRACT FROM AUTHOR]

In elastic materials, it is evident that the path of a propagating fracture is deflected from its normal course in presence of imperfections of the material or loading conditions. This paper aims at investigating hydraulic fracture deviation induced by non-uniformity of pore pressure fields with the use of a fully coupled poroelastic model based on the finite element method. The model includes a poroelastic domain in which pressurized hydraulic fractures are explicitly embedded, thus allowing to realistically model the fluid flow inside the fracture and to intrinsically consider the fracturing fluid load on the fracture walls as well as fluid leak-off into the formation. The latter process (fluid leak-off into the formation) controls both the length and the orientation of the fracture by changing the local pore pressure which in turn leads to a change in magnitude and direction of local principal stresses around the fracture tip. An innovative method, Mean Rotation Angle (MRA) is utilised for post-processing of evolving stress data at the vicinity of the fracture tip. The MRA predicts the potential growth path of pressurized fractures. In this paper pore pressure induced fracture reorientation is studied for a single fracture as well as closely spaced fractures. Results of this study indicate that presence of a pore pressure anomaly changes the growth path of a hydraulic fracture, towards or away from the anomaly. A higher than average pore pressure zone attracts the fracture while a lower pressure anomaly zone repulses the growing fracture. The fracture growth direction depends on the differential pressure and the distance between the anomaly and the fracture tip. Also in case of two simultaneously growing transverse fractures pressurized by injected fluid, it has been observed that the fluid leak-off controls the potential deviation angle of the fractures through changing the local pore pressure distribution pattern. It is shown that there are three distinct trends for the change of potential deviation angle due to fluid leak-off and that these three trends are linked to three corresponding stages of hydraulic communication between the two fractures. Furthermore, this study shows that change in matrix permeability, stress anisotropy, fracture half-length, spacing and the rate of leak-off influence the timing of each of the stages to the extent to which the corresponding stage of hydraulic communication of the two fractures are affected. This new understanding gives a better insight into the mechanism by which closely spaced hydraulic fractures interact and help optimize the design of multi-stage hydraulic fracture treatments. [ABSTRACT FROM AUTHOR]

When a hydraulic fracture (HF) is propagated in a shale reservoir, it may deflect and branch via intersections with natural fractures (NF) that exist in the shale, resulting in a dispersed HF-NF network and an enlarged simulated rock volume. This article explores geomechanical and geological factors that influence the HF-NF network configuration. NF in unconventional shale reservoirs are commonly infilled with mineral cement or have extremely narrow apertures. They are poor conduits for fluid movement but can be weak surfaces in the rock body that may open during HF stimulation. A HF can dilate the NF and deflect into the plane of a NF that it intersects only if the HF fluid pressure at the intersection exceeds the in situ normal stress resolved on the NF surface plus the strength of any mineral cement. The in situ stresses, the tensile strength of the NF and the net pressure (P net = HF fluid pressure -S hmin ) at the propagating front of the HF set limits on the range of NF orientations that can dilate and deflect the HF. A resolved stress plot facilitates assessment of the many geomechanical factors affecting the HF-NF interaction. The overall HF-NF network is composed of the main HF plus HF-NF branches comprising NF that have dilated connected by HF segments. A series of geometric models of NF populations are used to demonstrate how the orientation and size distribution of the NF in the shale, and the intensity of their development, limit the lateral spread of these branches. A broad dispersion of the HF-NF network is favored by a low in situ differential horizontal stress (ΔS h = S Hmax -S hmin ) and a high intensity of large and weakly cemented NF that are favorably oriented for dilation. Contrary conditions narrow the potential dispersion of the HF-NF network. [ABSTRACT FROM AUTHOR]

Spontaneous imbibition is a very important mechanism for the mass transfer between fracture and matrix in shale and tight reservoirs. To enhance this spontaneous imbibition, surfactants are added in imbibing fluids such as fracturing fluid and injection fluid. However, it has been observed in field applications that one group of wells having surfactants added in the fracturing fluid may not outperform another group of wells having no surfactants added. Oil operators start to ask: what types of surfactants should be used; what are the functions of the surfactants? Surfactants have two main functions: wettability alteration and reduction in interfacial tension (IFT). Which function is more important? This question needs to be answered so that we can choose the right types of surfactants to be added. This paper is to discuss the mechanisms of spontaneous imbibition and to answer this question. In this paper, we use simulation approach combined with theoretical analysis and published experimental results to investigate the mechanisms of spontaneous imbibition, and to compare the effects of capillary pressure, IFT reduction, diffusion and gravity. Particularly, we compare the effects of wettability alteration and IFT reduction. We find that the initial wettability is the most important factor to control imbibition. When a shale or tight rock is initially water-wet, the imbibition velocity is fast and the imbibition oil recovery is similar (about 10% lower in a simulated case) to that from a conventional rock. In that case, no surfactant is needed and thus the IFT is high oil-water IFT (20 mN/m in the models). When a shale or tight rock is initially oil-wet, a surfactant is added to change the wettability from oil-wet to water-wet, and the IFT is reduced to 0.008 mN/m). The imbibition velocity is found to be unrealistically slow. To achieve an oil recovery factor similar to that in the initially water-wet core plug in the lab scale, one million days of imbibition are needed. This results from the slow diffusion process. However, if the wettability is changed from oil-wet to water-wet and the IFT is maintained at a high value (20 mN/m), the oil recovery factor is similar to that from the initially water-wet core plug. These results show that the surfactant must be able to change wettability but to maintain high IFT to enhance the imbibition in a shale or tight reservoir. Further studies of the effects of IFT reduction without wettability alteration, diffusion and gravity indicate that these mechanisms are not practically effective in shale and tight reservoirs, because either the viscous force cannot be overcome or the processes are too slow. The findings of this paper provide a guide regarding what type of surfactants should be used to enhance the fracture-matrix mass transfer by spontaneous imbibition. [ABSTRACT FROM AUTHOR]

The stability of the horizontal long section wellbore is the key factor of restricting the efficient development of shale gas. High clay mineral content and developed microfractures of shale reservoir make the problems of formation damage and horizontal wellbore stability more complex. OBDF (Oil-based drill-in fluid) is widely used to control formation damage and prevent wellbore instability in shale gas wells. However, high cost and serious environmental problem severely restrict the economic development of shale gas. In order to meet the requirement of cost reduction and environmental protection during shale gas drilling operation, drilling horizontal well with WBDF (water-based drill-in fluid) instead of OBDF has become one of the engineering technology problems to be solved urgently. The Longmaxi shale in Sichuan Basin of China and the associated drill-in fluids at the site are the object of our research. Evaluation experiments on liquid damage and sealing capacity of drill-in fluids were conducted to recognize and optimize the properties of oil-based and water-based drill-in fluids in shale reservoir. Combining the methods of particle size distribution, friction coefficient testing, alkali erosion, linear expansion and immersion test, we investigated the effect of drill-in fluids on formation damage and wellbore stability. Results show that the damage degree of OBDF filtrate on shale is more severe than that of WBDF filtrate. Fracture sealing and bi-directional pressure containment capacity of WBDF is also stronger than that of OBDF. Due to the invasion of OBDF with high pH value, the friction strength of the fracture surface decreases and frictional sliding will take place, which can cause the wellbore instability. With the WBDF immersion, microfractures initiate and propagate along the bedding surface for the shale hydrate expansion, and lead to wellbore instability. The results of our analysis suggest that OBDF does not completely solve the problems of formation damage and wellbore instability in shale reservoir, and reinforcing the sealing fracture and inhibiting hydration capacity of WBDF will contribute to its wider application in shale reservoir. This study provides a theoretical guidance for drill-in fluid selection and optimization during the operation of shale gas well drilling. [ABSTRACT FROM AUTHOR]

It is well acknowledged that water injection may induce formation fracturing in tight reservoir, and the injection well may experience shrinking fracture length (SFL) and variable fracture conductivity (VFC) during fracture-falloff period, which shows the bi-storage behavior. However, available pressure-transient analysis (PTA) models hardly consider these effects (SFL, VFC and bi-storage behavior) on pressure-transient response, which can lead to erroneous results. This paper aims at presenting an innovative approach to model the water injection wells considering the dynamic characteristics of waterflood-induced fracture (WIF). We first modeled fluid flow between reservoir and the fracture which characterized by fracture-storage coefficient and fracture-face skin factor, and flow between wellbore and the fracture which represented by wellbore-storage coefficient and choked-fracture skin factor. In addition, the effects of SFL and VFC were included by finite difference method. A semi-analytical solution was then derived to model injection well with waterflood-induced fracture (IWWIF). Finally, this methodology has been successfully applied in Changqing oilfield, China. There are six flow regimes for the IWWIF model in the tight reservoir, including wellbore-storage regime, transitional-flow regime, fracture-storage regime, the second transitional regime, linear flow regime and bilinear flow regime. Compared to current models, the bi-storage phenomenon is discovered and validated as two straight lines with unit slope in the pressure derivate curve of type plot. The WIF that closely links with the wellbore can be regarded as an “expanding wellbore”, which illustrates the reason that the “wellbore-storage coefficients” are increased by up to several orders of magnitude in a great many of water injection wells. The VFC behavior could cause the upward of pressure-derivative curve, which is generally recognized as the characteristic of closed boundary condition while the variable fracture-storage effect may occur because of SFL. In addition, the relation between matched fracture-storage coefficient and fracture length is given, which provides us another way to obtain the probable length of WIF. Finally, this new model has been successfully used to evaluate well performance and reservoir characteristics based on bottom-hole pressure (BHP) history of five field cases in Changqing oilfield, China. [ABSTRACT FROM AUTHOR]

The principal focus of this paper is on pressure-transient analysis for a finite-conductivity fracture at an arbitrary azimuth in a rectangular anisotropic reservoir. An analytical solution is derived by spatial integration of point-source along the direction of the fracture for a fracture at an arbitrary azimuth in a rectangular reservoir. Furthermore, type curves are generated to investigate the influence of the main parameters on transient pressure behavior, including permeability anisotropy, azimuth of the fracture, reservoir's outer boundary, and fracture conductivity. Strong effects of horizontal permeability anisotropy and azimuth of a fracture on transient responses can be observed. The more the fracture deviates from the direction of maximum horizontal permeability, lesser the drawdown needed to maintain constant flow rate. Therefore, it seems that the optimum orientation for the hydraulic fracture is perpendicular to the direction of maximum horizontal permeability. Outer boundary size dominates pseudo-steady-state flow and aspect ratio mainly affects the periods of radial flow and compound-linear flow. The existence and duration of bilinear flow and formation linear flow are mainly determined by dimensionless fracture conductivity. This paper provides a theoretical basis for well pattern deployment and fracture configuration in anisotropic reservoirs. [ABSTRACT FROM AUTHOR]

Multi-layer commingling coalbed methane (CBM) development causes interlayer interference, which can severely impede the efficient pressure drop in CBM reservoirs and make it difficult to identify the produced water source. In this study, geochemical analyses (conventional ions, stable isotopes, and trace elements) were conducted on 38 water samples collected from 11 CBM wells, an adjacent river and the coal mine in the Bide-Santang Basin, western Guizhou, China. Variations in water quality caused by aquifer recharge, water-rock interactions, and the oxidation environment were revealed using principle component analysis and hierarchical cluster analysis. Li, Ga, Rb, Sr, and Ba were selected as characteristic trace elements, whose concentrations tend to increase with increasing producing layer depth. The water samples recorded an obvious D drift trend relative to the local meteoric water line (LMWL). Fracturing fluid from contaminated wells recorded elevated Cl − and Na + concentrations and high δ 18 O and δ D values. The geochemical parameters of d (the degree of D drift), δ D, δ 18 O, Cl − + Na + and characteristic trace element concentrations in produced water serve as indicators of the production and water source of CBM wells. Templates were created to discriminate between sources of produced water, including shallow groundwater, coal seam water, and fracturing fluid water. High-production wells are characterized by producing coal seam water, while low-production wells are characterized by producing shallow groundwater. The upper CBM system is susceptible to shallow groundwater recharge that involves multiple limestone aquifers, so it is recommended that the middle and lower CBM systems should be a priority for CBM development. [ABSTRACT FROM AUTHOR]

Hydrofluoroether C 4 F 9 OCH 3 , as a foaming agent in liquid CO 2 , is used to stabilize bubble in liquid CO 2 -based foam fracturing fluid which is waterless and no damage to oil-gas reservoir. However, characteristics of this environmental friendly CO 2 -based foam, such as the foam morphology and its flow behaviors in pipe, are insufficiently understood. Especially, foam quality, one of important characteristic parameters in a foam fluid, has significant effects on foam structure and flow behaviors of CO 2 -based foam. By means of the flow tests in pipes with different diameters, it was found that the CO 2 -based foam displayed wall slip phenomenon, and Oldroyd-Jastrzebski method was used to deal with this phenomenon. Effective viscosity of this CO 2 -based foam, as well as convective heat transfer coefficient initially increases and then decreases with the increase of foam quality. Due to dominant collision and friction among bubbles, their values reach the corresponding maximums when the foam quality is about 0.82. Meanwhile, the evolution of rheological parameters of CO 2 -based foam with the foam quality is shown as well, and the exponential relationship between yield stress and foam quality is illustrated. Additionally, as for the flow friction characteristics, it shows that fanning friction factor increases and drag reduction rate initially increases and then decreases as the foam quality is increased. [ABSTRACT FROM AUTHOR]